Traditionally wells drilled deep into the earth, and in particular wells driven into underground hydrocarbon formations for purposes of extracting oil and gas, have been drilled through circulating a drilling fluid or mud downwardly through a drill string to the bottom of the well and then subsequently up the annulus between the string and the well casing. The drilling fluid serves the primary purposes of exerting hydrostatic pressure upon the underground formation in an attempt to prevent the entry of hydrocarbons or other native fluids into the wellbore and provides a means by which rock cuttings and other debris may be carried upwardly and expelled from the well. In situations where the well is being drilled through the use of a downhole motor, the circulating mud or fluid also serves as a means of energizing, cooling and lubricating the downhole motor.
When drilling deep wells, or wells through formations containing highly pressurized fluids, commonly a high density drilling mud is used in order to obtain a sufficient hydrostatic pressure (overbalanced) at the bottom of the well to prevent the influx of fluids into the wellbore and to maintain well control. Unfortunately, with the added level of control and enhanced level of safety that may be achieved through the use of a heavy, high density, drilling mud there also comes the drawback that the mud may be forced into or penetrate the hydrocarbon zone, particularly where such zones exist in porous, fractured or permeable formations. The loss or penetration of drilling mud into the underground formation not only affects the economics of the drilling operation through the need to use greater volumes of mud (which in some instances may contain expensive density enhancing materials), but can also affect the productivity of the well after the drilling operations have ceased. That is, the penetration of drilling mud into the hydrocarbon formation can damage the underground formation and later impede the flow of hydrocarbons into the well during the production phase.
In an effort to avoid the problems associated with overbalanced drilling, others have utilized a drilling method where a low density or light drilling fluid or mud is circulated through the well creating a bottom hole pressure that is generally below that of the underground hydrocarbon formation so that drilling fluid does not penetrate the formation. This method is known generally as underbalanced drilling but is sometimes also referred to as controlled pressure drilling or managed pressure drilling, and may include foam drilling, flow drilling and gas or dust drilling. When drilling underbalanced, the drilling fluid (which may be water, diesel fuel, or a variety of other low density fluids) is typically “lightened” with an added gas and used as the circulating medium upon entry into the underground hydrocarbon formation. Most commonly the gas used to lighten the drilling fluid is nitrogen due to its availability, cost, and the fact that it is inert. Other gases may also be used, depending upon their availability and cost. In most instances the gas will be added to the drilling fluid at the surface but in some instances it may be introduced at the base of the drill string or at a casing/casing or liner/casing transition point through the use of a parasite string or a concentric casing. Where the service gas is nitrogen it is typically derived from a cryogenic source or generated on site by means of an exhaust gas or membrane generation system. In some instances natural gas may be used in place of nitrogen, however, there will still exist the necessity for an inert gas for purging purposes, such as when making a connection and before tripping pipe out of the hole.
As the drilling fluid is circulated through a well during underbalanced drilling, the well returns at the surface will typically comprise the initial drilling fluid (which as indicated may be water, diesel fuel or other fluid), rock cuttings, and the gas that was added to lighten or reduce the fluid's density. Where the well is drilled through an underground hydrocarbon formation, the drilling returns may also include oil and/or gaseous hydrocarbons. In such situations the well returns are typically passed through a separation vessel to separate the solid, liquid and gas phases. The separated gases are commonly vented or flared. Alternatively, and as suggested in U.S. Pat. No. 5,775,442, the separated gases may be recycled back to the drill pipe.
Where the separated drilling returns contain natural gas, flaring is often not an attractive option on the account of environmental concerns and the reluctance to waste a valuable resource. Where natural gas pipelines are within close proximity the separated gas can be sent to a compression stage and injected into the gas pipeline presenting a potential source of revenue. While such prior systems may be advantageous from the perspective of avoiding having to send gas to flare, they still require the use of relatively extensive compression equipment that adds both to the capital and operating costs of the project. In addition, regardless of the level of recycling or injection of natural gas into the well, service gas will still be required during start up of the operation. An inert gas source must also be available for purging. It has therefore been historically necessary to have a standard inert or service gas system readily available at the drill site. Such inert gas systems are often capital intensive and require significant amounts of energy to generate the volumes of inert gas that are required for start up and for drilling purposes.